InPlay Oil Corp. Announces Record Setting 2021 Financial, Operating and Reserves Results

News and Market Data on InPlay Oil Corp

 

CALGARY, Alberta, March 16, 2022 (GLOBE NEWSWIRE) — InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the “Company”) announces its record setting financial and operating results for the three and twelve months ended December 31, 2021, and the results of its independent oil and gas reserves evaluation effective December 31, 2021 (the “Reserve Report”) prepared by Sproule Associates Limited (“Sproule”). InPlay’s audited annual financial statements and notes, as well as Management’s Discussion and Analysis (“MD&A”) for the year ended December 31, 2021 will be available at “www.sedar.com” and our website at “www.inplayoil.com”.

2021 Highlights:

• Completed the acquisition of Prairie Storm Resources Corp. on November 30, 2022 at attractive transaction metrics which enhances InPlay’s position as a sizable producer and acreage holder with a deep and highly economic drilling inventory in the light oil window of Central Alberta’s Cardium fairway.
• Achieved record average annual production of 5,768 boe/d⁽¹⁾ (65% light crude oil and NGLs), an increase of 45% from 2020 at 3,985 boe/d⁽¹⁾ (68% light crude oil and NGLs) and an increase of 15% compared to pre-COVID levels of 5,000 boe/d⁽¹⁾ (66% light crude oil and NGLs) in 2019. Annual average production per weighted average basic share increased 31% compared to 2020.
• Generated record annual adjusted funds flow (“AFF”)⁽²⁾ of $47.0 million ($0.67 per weighted average basic share⁽³⁾), an increase of 532% compared to $7.4 million ($0.11 per weighted average basic share) in 2020 and an increase of 45% compared to $32.5 million ($0.48 per weighted average basic share) in 2019, our prior record year. Excluding the impact of realized hedging losses, AFF for 2021 would have been $59.9 million.
• Increased operating netbacks⁽⁴⁾ by 203% to $34.63/boe from $11.45/boe in 2020 and 52% from $22.75/boe in 2019.
• Realized annual record operating income⁽⁴⁾ and operating income profit margin⁽⁴⁾ of $72.9 million and 64% respectively compared to $16.7 million and 40% in 2020; $41.5 million and 55% in 2019.
• Reduced operating expenses to an annual record $12.83/boe compared to $14.43/boe in 2020 and $14.36/boe in 2019, despite rising costs of services in the industry.
• Generated annual free adjusted funds flow (“FAFF”)⁽⁴⁾ of $13.6 million.
• Lowered annual net debt⁽²⁾ to earnings before interest, taxes and depletion (“EBITDA”)⁽⁴⁾ ratio to 1.5, compared to 6.7 in 2020 and 1.6 in 2019. Fourth quarter 2021 annualized net debt to EBITDA ratio was 1.1 compared to 4.0 in 2020 and 1.6 in 2019 achieving the lowest leverage ratios in our corporate history.
• Achieved significant growth in reserves and reserves per weighted average basic share:
  • Proved developed producing (“PDP”) reserves increased 64% (61% per weighted average basic share) to 15,890 mboe (58% light and medium crude oil & NGLs)
  • Total proved (“TP”) reserves increased 112% (106% per weighted average basic share) to 45,891 mboe (62% light and medium crude oil & NGLs)
  • Total proved plus probable (“TPP”) reserves increased 85% (81% per weighted average basic share) to 60,640 mboe (63% light and medium crude oil & NGLs)
• Achieved record NPV BT10 reserve and net asset values (“NAV”)⁽⁶⁾:
  • NPV BT10: $206 million (PDP), $471 million (TP) and $686 million (TPP)
  • NAV: $1.85 per weighted average basic share (PDP), $4.92 per weighted average basic share (TP) and $7.41 per weighted average basic share (TPP)
  • West Texas Intermediate (“WTI”) prices used in the Reserve Report to value the Company’s reserves are approximately 22% and 15% less than current strip pricing for 2022 (US $72.83 vs. approximately US $89.00) and 2023 (US $68.78 vs. approximately US $79.00) respectively.
• Finding, Development and Acquisition (“FD&A”)⁽⁵⁾ costs, associated recycle ratios and capital efficiencies which are top tier amongst light oil weighted peers.
  • FD&A⁽⁵⁾ costs of $8.47/boe (PDP), $12.03/boe (TP) and $9.56/boe (TPP), consistent with three year averages of $9.67/boe (PDP), $10.98/boe (TP) and $9.23 (TPP).
  • Recycle ratios⁽⁵⁾ of 4.1 (PDP), 2.9 (TP) and 3.6 (TPP) compared to 1.2 (PDP), 2.0 (TP) and 1.4 (TPP) in 2020.
  • InPlay added new light oil weighted production at a capital efficiency⁽⁵⁾ of $12,583 per boe/d.
• Materially increased the reserve life index of our assets which in turn improves the long term sustainability of the Company:
  • PDP reserve life index⁽⁵⁾ of 7.5 years compared to 6.6 years in 2020
  • TP reserve life index of 21.8 years compared to 14.8 years in 2020
  • TPP reserve life index of 28.8 years compared to 22.5 years in 2020
• Successful development and A&D activity resulting in top-tier reserve replacement⁽⁵⁾:
  • PDP replacement of 395% (2020 – 166%)
  • TP replacement of 1,253% (2020 – 309%)
  • TPP replacement of 1,422% (2020 – 479%)
• Increased liquidity through an increased capacity within our Senior Credit Facility from $65.0 million to $85.0 million and total debt capacity of $111 million.
• Abandonment and Reclamation Obligations spending of $2.3 million, reducing our liability by 3% through the successful abandonment of 75 wellbores and the reclamation of 22 well sites.
• Achieved a 20% reduction to the Company’s emissions (Scope 1 and 2) on a per boe basis compared to 2020.
  
  

Notes:

1. See “Reader Advisories – Production Breakdown by Product Type”
2. Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
3. Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
4. Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures”.
5. “FD&A”, “recycle ratio”, “reserve replacement”, “reserve life index” and “capital efficiency” do not have standardized meanings and therefore may not be comparable to similar measures presented for other entities. Refer to section “Performance Measures” for the determination and calculation of these measures.
6. See “Corporate Reserves Information” and “Net Asset Value” for detailed information from the Reserve Report and associated calculations.

Message to Shareholders:

The Company exited 2021 in its best operational and financial position to date. The disciplined and measured steps taken during 2020 and 2021, allowed us to implement a strategy focused on measured growth combined with generating strong free adjusted funds flow once oil prices began to recover in mid-2021. InPlay initially directed its free adjusted funds flow to debt reduction ensuring a strong and sustainable balance sheet from which to grow the Company. The strategy led to record annual AFF of $47.0 million and record annual FAFF of $13.6 million for the year while also reducing net debt, resulting in InPlay’s lowest historic leverage ratios. As the Company solidified its financial position, the strategy evolved to the point where InPlay was able to evaluate and execute upon accretive acquisition opportunities. Following up on a small but highly successful tuck-in acquisition during Q4 2020 (where InPlay grew production from 300 boe/d to 2,900 boe/d⁽²⁾ in Q4 2021), InPlay closed the highly accretive corporate acquisition of Prairie Storm Resources Corp. on November 30, 2022. This acquisition enhanced the Company’s sustainability by adding low decline production, sizeable economic drilling inventory that complements InPlay’s own high internal rate of return, quick payout inventory, and increased reserve life while also adding material scale to the Company. All of these attributes enhance InPlay’s ability to grow and to continue to generate sustained long term FAFF per share⁽¹⁾. Immediately post closing, InPlay started drilling two wells on the Prairie Storm lands with results exceeding our expectations, confirming our technical evaluation of the assets. InPlay management is proud to be able to consistently deliver top tier reserve, production and AFF per share growth while also generating significant FAFF per share growth.

The Company’s sustainability has improved significantly with a very strong weighting of PDP reserves relative to TP and TPP reserves which now represent approximately 35% and 26% of the Company’s TP and TPP reserves respectively, with long-life reserves providing RLI’s of 7.5 years (PDP), 21.8 years (TP) and 28.8 years (TPP). InPlay’s long life reserves combined with the expected 2022 PDP base production decline rate of 23.2% (compared to 25.9% in 2021) puts the Company in a solid position to sustainably deliver long term per share growth and shareholder returns.

InPlay continued to deliver on our track record of drilling efficiency, operational expertise and accretive strategic acquisition activity, driving attractive light oil reserve addition metrics. FD&A costs per boe were $8.47, $12.03 and $9.56 in PDP, TP and TPP reserve categories respectively. These costs were consistent with InPlay’s three year FD&A averages of $9.67/boe (PDP), $10.98/boe (TP) and $9.23 (TPP). The Prairie Storm acquisition provided highly accretive and economic reserve additions that are expected to generate strong production and FAFF growth. The 2021 capital program continued to convert the Company’s high quality drilling inventory into reliable cash flow capital efficiencies of $12,583 per boe/d, representing a new record for the Company.

Notes:

1. Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures”.
2. See “Production Breakdown by Product Type” at the end of this press release.

2022 Outlook Update

InPlay’s focus has been concentrated on reducing debt and improving leverage ratios. Execution of this focus is significantly ahead of schedule with the increased commodity prices. With our sound financial footing and projected liquidity capacity, InPlay is expected to be able to deliver measured production per share growth and strong free adjusted funds flow which positions the Company to execute on strategic accretive opportunities with the ultimate goal of maximizing returns to shareholders.

 

InPlay is forecasting 2022 to be another record year for the Company, and reiterates its previously announced January 12, 2022 average production guidance of 8,900 to 9,400 boe/d⁽¹⁾. With the recent sustained increase in commodity prices, we are updating our price forecast using USD $90/bbl WTI, $4.30/mcf AECO and a CAD/USD exchange rate of 0.80. Based on this revised commodity price forecast, InPlay is now expected to generate 2022 AFF of $141 to $150 million and 2022 FAFF of $83 to $92 million which would result in InPlay being in a positive working capital position, in excess of debt, by year end. 

The table below outlines InPlay’s financial results of the board approved capital budget based on several WTI pricing scenarios for the remainder of 2022 (assuming an average Q1/22 WTI price of US$91.50/bbl):

Notes:

1. See “Production Breakdown by Product Type” at the end of this press release.
2. This reflects the mid-point of the Company’s 2022 production guidance range of 8,900 to 9,400 boe/d.
3. Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures”.
4. Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release. .
5. See “Reader Advisories – Forward Looking Information and Statements” for key budget and underlying assumptions related to our 2022 capital program and associated guidance.
6. Assumes a share price of $3.06.

Operations Update

InPlay’s capital program for the first quarter of 2022 was initiated in mid December 2021 due to the availability of services and the desire to take advantage of strong commodity prices, including winter natural gas prices. The two (1.6 net) wells that were drilled in December 2021 on the Prairie Storm lands were brought on production in the second half of January and are currently exceeding forecasts. The average initial production (“IP”) rates from these wells are as follows:

An additional three (3.0 net) Extended Reach Horizontal (“ERH”) wells were drilled in Pembina during January and February and were brought on production ahead of schedule in late February. These wells are in the early clean up stage and are also currently producing above forecasts. The average combined IP rates from these wells are as follows:

IP 15 (% light crude oil and NGLs)	Current (% light crude oil and NGLs)
1,022 boe/d (79%)	1,354 boe/d (71%)

Current corporate production is approximately 9,050 boe/d⁽¹⁾ (62% light crude oil and NGLs), based on field estimates.

Plans for the remainder of the first quarter of 2022 consist of completing two (1.7 net) wells that were drilled on our recently acquired Prairie Storm lands. These wells are expected to be on production before the end of the first quarter. In addition, InPlay will bring on production one (0.2 net) non-operated Cardium ERH well.

Looking forward, the Company has started capital preparations for the second quarter of 2022. Due to strong commodity prices and access to our preferred service providers, the Company expects to start the second quarter drilling program early, with certain operations including lease construction already completed. It is expected that drilling operations will commence approximately six weeks ahead of schedule.

Notes:

1. See “Production Breakdown by Product Type” at the end of this press release.
2. Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures”.

Financial and Operating Results:

2021 Financial & Operations Overview:

Production averaged 5,768 boe/d (65% light crude oil & NGLs) ⁽¹⁾ in 2021, a 45% increase compared to 3,985 boe/d (68% light crude oil & NGLs)⁽¹⁾ in 2020 and a 15% increase compared to 5,000 boe/d (66% light crude oil & NGLs)⁽¹⁾ in 2019. The four quarter sales volumes were slightly affected due to the following factors; operational downtime caused by extreme cold, third party processing facility shut downs and a larger build in period ending oil inventories of approximately 9,000 barrels.

InPlay’s 2021 capital program consisted of $33.4 million of development capital. The Company drilled eight (8.0 net) ERH wells in Pembina, and two (1.6) Willesden Green ERH wells on our newly acquired Prairie Storm assets during the year, for a total of 12 (10.0 net) wells drilled during the year. The Company also participated in one (0.2 net) Nisku ERH well and one (0.2 net) Willesden Green ERH well in 2021. This activity amounted to the drilling of an equivalent of 20.5 gross horizontal miles (15.4 net horizontal miles). This capital spending also included the construction of a multi-well battery in Pembina, which is anticipated to accommodate future development in the area over the next three years. InPlay also accelerated the start of its 2022 capital program at the end of 2021, initiating construction operations and the start of drilling activities on a three well pad in Pembina due to optimal timing and availability of services.        

Efficient field operations resulted in the Company achieving record low operating costs of $12.83/boe. This result was achieved despite rising power costs throughout the year and in services in the second half of the year. The resulting operating income⁽²⁾ and operating income profit margin⁽²⁾ for 2021 were also annual records for the Company at $72.9 million and 64% respectively.

Note:

1. See “Reader Advisories – Production Breakdown by Product Type”
   
2. Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures”.

2021 Reserves Overview:

As a result of the Company’s efficient execution of development capital in 2021, strategic A&D activity and the quality of our asset base, significant reserve growth was generated in all reserve categories compared to 2020. PDP reserves increased by 64% in 2021 to 15,890 mboe, TP reserves increased by 112% to 45,891 mboe and TPP reserves increased by 85% to 60,640 mboe. This reserve based growth easily replaced our 2021 production, with 395% of production being replaced on a PDP basis, 1,253% on a TP basis and 1,422% on a TPP basis.

This significant reserve growth and improvements to commodity prices resulted in strong 2021 year-end reserve net present values of future net revenues before tax (“NPV BT”) and net asset values per basic share (“NAVPS”). This resulted in reserve values of NPV BT10 of $206 million (PDP), $471 million (TP) and $686 million (TPP) using a three independent reserve evaluators average pricing forecast and foreign exchange rates as at December 31, 2021 as used in the Reserve Report. This equates to Net Asset Values of $160 million and $1.85 NAVPS (PDP), $424 million and $4.92 NAVPS (TP) and $639 million and $7.41 NAVPS (TPP)⁽¹⁾, representing 81% (PDP), 154% (TP) and 112% (TPP) growth for each category respectively on a per weighted average basic share basis over 2020.

Note:

1. See “Net Asset Value” for detailed calculations.
   

Corporate Reserves Information:

The following summarizes certain information contained in the Reserve Report. The Reserve Report was prepared in accordance with the definitions, standards and procedures contained in the COGE Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form (“AIF”) which will be filed on SEDAR by the end of March 2022.

Notes:

1. Reserves have been presented on a gross basis which are the Company’s total working interest (operating and non-operating) share before the deduction of any royalties and without including any royalty interests of the Company.
2. Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2021, as outlined in the table herein entitled “Pricing Assumptions”.
3. It should not be assumed that the NPV amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of InPlay’s light and medium crude oil, natural gas liquids and conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual light and medium crude oil, conventional natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
4. All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment, decommissioning and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis.
5. The Company has included abandonment, decommissioning and reclamation costs for all active and inactive assets including non-producing and suspended wells, facilities and pipelines. December 31, 2021 reserve NPV values are also inclusive of currently enacted carbon taxes.
6. Totals may not add due to rounding.

Net Asset Value:

Notes:

1. Evaluated by Sproule as at December 31, 2021. The estimated NPV does not represent fair market value of the reserves.
2. Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2021.
3. Duvernay land holdings attributed a value of $19.9 million ($847/acre) for 23,440 net acres based on internal valuations. The remaining undeveloped acreage is based on an internal valuation totaling $13.6 million ($256/acre) for 53,159 net acres. These internal valuations are based on land sale results in the area.
4. Net debt as at December 31, 2021.
5. Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
6. Based upon 86,214,751 common shares outstanding as at December 31, 2021.

Future Development Costs (“FDCs”):

FDCs increased by $246.9 million on a Total Proved basis and $215.7 million on a Total Proved plus Probable basis.

Future Development Capital Costs (amounts in $million)
	Total Proved	Total Proved + Probable
2022	58.9	66.6
2023	99.2	111.7
2024	100.5	114.0
2025	95.3	110.5
Remainder	62.7	71.4
Total undiscounted FDC	416.7	474.2
Total discounted FDC at 10% per year	332.4	377.8

Note: FDC as per Reserve Report based on forecast pricing as outlined in the table herein entitled “Pricing Assumptions”

Performance Measures:

In 2021, InPlay’s successful exploration, development and acquisition/disposition capital program achieved a capital efficiency of $12,583 per boe/d and a three year average of $15,354 per boe/d.⁽⁷⁾

Notes:

1. Finding, Development & Acquisition (“FD&A”) costs are used as a measure of capital efficiency. The calculation includes the period’s capital expenditures, including Exploration and Development (“E&D”) and Acquisition and Disposition (“A&D”) expended in the year, less capitalized G&A expenses and undeveloped land expenditures acquired with no reserves. This total of capital expenditures, including the change in the FDC over the period, is then divided by the change in reserves, other than from production, for the period incorporating additions/reductions from extensions, infill drilling, technical revisions, acquisitions/dispositions and economic factors. For example: 2021 TPP = ($33.4 million E&D – $1.2 million capitalized G&A – $nil million of land acquisitions + $38.2 million net acquisition/disposition capital + $215.8 million FDC) / (60,640 mboe – 32,816 mboe + 2,105 mboe) = $9.56 per boe. Finding and Development Costs (“F&D”) are calculated the same as FD&A costs, however adjusted to exclude the capital expenditures and reserve additions/reductions from acquisition/disposition activity. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
2. Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures”
3. See “Reader Advisories – Production Breakdown by Product Type”
4. Recycle Ratio is calculated by dividing the year’s operating netback per boe by the FD&A costs for that period. For example: 2021 TPP = ($34.63/$9.56) = 3.6. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
5. The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year. For example: 2021 TPP = (60,640 mboe – 32,816 mboe + 2,105 mboe) / 2,105 mboe = 1422%, which reflects the extent to which the Company was able to replace production and add reserves throughout the year.   See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
6. RLI is calculated by dividing the reserves in each category by the 2021 average annual production. For example 2021 TPP = (60,640 mboe) / (5,768 boe/day) = 28.8 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
7. Capital Efficiency is calculated as the total annual exploration & development and acquisition and disposition capital expended in the year, less capitalized G&A and land acquisition costs divided by production additions comparing the fourth quarter of the previous year using a decline rate of 29% over the course of the year, calculated as follows: ($33.4 million E&D – $1.2 million capitalized G&A – $nil million of land acquisitions – $0.1 million net acquisition/disposition capital + $9.2 million of 2020 capital adding reserves in 2021 – $3.0 million of capital not adding reserves in 2021) / (Q4/2021 production of 6,687 boe/d – Q4/2020 production of 4,259 boe/d + 2021 declined production at 29% of 1,218 boe/d – Q4/2021 Prairie Storm production of 600 boe/d). See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories.
   

Pricing Assumptions:

The following tables set forth the benchmark reference prices, as at December 31, 2021, reflected in the Reserve Report. These price assumptions were an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at the effective date of the Reserve Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS ⁽¹⁾
as of December 31, 2021
FORECAST PRICES AND COSTS

 

Notes:

1. This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
2. The exchange rate used to generate the benchmark reference prices in this table.
3. As at December 31, 2021.
   
   

Environmental, Social and Governance (“ESG”) Update

InPlay’s commitment to ESG is evident through its operational track record, corporate culture and strong governance. The Company is pleased to announce that it expects to release its inaugural sustainability report this summer. InPlay looks forward to sharing the Company’s strategy and governance related to ESG and reporting ESG related metrics with shareholders.

The Company completed an active abandonment and reclamation program throughout 2021, spending $2.3 million on the abandonment of 75 wellbores and the reclamation of 22 well sites. This resulted in a reduction to our Abandonment and Reclamation obligation of 3% during 2021. Efficient field operations resulted in a 20% reduction to the Company’s emissions (Scope 1 and 2) on a per boe basis compared to 2020.

Included in our 2022 forecast is a commitment to materially reducing the Company’s abandonment and reclamation obligations. Approximately 30 abandonment operations and 20 reclamations are currently planned for 2022, which is estimated to result in a $3 million or 3% reduction to our ARO and a projected improvement in our Liability Management Rating (“LMR”) to 2.85.

We look forward to continuing to deliver returns to our shareholders and thank all of those that have supported InPlay since the Company’s inception. The future for InPlay and the industry are very promising and we will continue to operate the Company in a prudent, sustainable and responsible manner.

For further information please contact:

Doug Bartole		Darren Dittmer
President and Chief Executive Officer		Chief Financial Officer
InPlay Oil Corp.		InPlay Oil Corp.
Telephone: (587) 955-0632		Telephone: (587) 955-0634

 

Reader Advisories

Non-GAAP and Other Financial Measures

Throughout this press release and other materials disclosed by the Company, InPlay uses certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed under GAAP and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with GAAP as indicators of the Company performance. Management believes that the presentation of these non-GAAP and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company’s ongoing operating performance, and the measures provide increased transparency and the ability to better analyze InPlay’s business performance against prior periods on a comparable basis.

Non-GAAP Financial Measures and Ratios

Included in this document are references to the terms “free adjusted funds flow”, “free adjusted funds flow per share”, “FAFF Yield”, “operating income”, “operating netback per boe”, “operating income profit margin”, “Net Debt to EBITDA”, “Net corporate acquisitions”, “Debt adjusted production per share” and “EV / DAAFF”. Management believes these measures are helpful supplementary measures of financial and operating performance and provide users with similar, but potentially not comparable, information that is commonly used by other oil and natural gas companies. These terms do not have any standardized meaning prescribed by GAAP and should not be considered an alternative to, or more meaningful than “profit (loss) before taxes”, “profit (loss) and comprehensive income (loss)”, “adjusted funds flow”, “capital expenditures”, “corporate acquisitions, net of cash acquired”, “net debt”, “weighted average number of common shares (basic)” or assets and liabilities as determined in accordance with GAAP as a measure of the Company’s performance and financial position.

Free Adjusted Funds Flow / FAFF per share

Management considers free adjusted funds flow and free adjusted funds flow per share important measures to identify the Company’s ability to improve its financial condition through debt repayment, which has become more important recently with the introduction of second lien lenders, on an absolute and weighted average per share basis. Free adjusted funds flow should not be considered as an alternative to or more meaningful than adjusted funds flow as determined in accordance with GAAP as an indicator of the Company’s performance. Free adjusted funds flow is calculated by the Company as adjusted funds flow less exploration and development capital expenditures and property dispositions (acquisitions) and is a measure of the cashflow remaining after capital expenditures before corporate acquisitions that can be used for additional capital activity, corporate acquisitions, repayment of debt or decommissioning expenditures. Free adjusted funds flow per share is calculated by the Company as free adjusted funds flow divided by weighted average outstanding shares. Refer below for a calculation of free adjusted funds flow, free adjusted funds flow per share and a reconciliation of free adjusted funds flow to the nearest GAAP measure, adjusted funds flow.

Free Adjusted Funds Flow Yield

InPlay uses “free adjusted funds flow yield” as a key performance indicator. Free adjusted funds flow is calculated by the Company as free adjusted funds flow divided by the market capitalization of the Company. Management considers FAFF yield to be an important performance indicator as it demonstrates a Company’s ability to generate cash to pay down debt and provide funds for potential distributions to shareholders. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast 2022 free adjusted funds flow yield.

Operating Income/Operating Netback per boe/Operating Income Profit Margin

InPlay uses “operating income”, “operating netback per boe” and “operating income profit margin” as key performance indicators. Operating income is calculated by the Company as oil and natural gas sales less royalties, operating expenses and transportation expenses and is a measure of the profitability of operations before administrative, share-based compensation, financing and other non-cash items. Management considers operating income an important measure to evaluate its operational performance as it demonstrates its field level profitability. Operating income should not be considered as an alternative to or more meaningful than net income as determined in accordance with GAAP as an indicator of the Company’s performance. Operating netback per boe is calculated by the Company as operating income divided by average production for the respective period. Management considers operating netback per boe an important measure to evaluate its operational performance as it demonstrates its field level profitability per unit of production. Operating income profit margin is calculated by the Company as operating income as a percentage of oil and natural gas sales. Management considers operating income profit margin an important measure to evaluate its operational performance as it demonstrates how efficiently the Company generates field level profits from its sales revenue. Refer below for a calculation of operating income, operating netback per boe and operating income profit margin.

Net Debt to EBITDA
Management considers Net Debt to EBITDA an important measure as it is a key metric to identify the Company’s ability to fund financing expenses, net debt reductions and other obligations. EBITDA is calculated by the Company as adjusted funds flow before interest expense. This measure is consistent with the EBITDA formula prescribed under the Company’s Senior Credit Facility. Net Debt to EBITDA is calculated as Net Debt divided by EBITDA. Refer below for a calculation of Net Debt / EBITDA.

Net Corporate Acquisitions
Management considers Net corporate acquisitions an important measure as it is a key metric to evaluate the corporate acquisition in comparison to other transactions using the negotiated consideration value and ignoring changes to the fair value of the share consideration between the signing of the definitive agreement and the closing of the transaction. Net corporate acquisitions should not be considered as an alternative to or more meaningful than “Corporate acquisitions, net of cash acquired” as determined in accordance with GAAP as an indicator of the Company’s performance. Net corporate acquisitions is calculated as total consideration with share consideration adjusted to the value negotiated with the counterparty, less working capital balances assumed on the corporate acquisition. Refer below for a calculation of Net corporate acquisitions and reconciliation to the nearest GAAP measure, “Corporate acquisitions, net of cash acquired”.

Production per Debt Adjusted Share

InPlay uses “Production per debt adjusted share” as a key performance indicator. Debt adjusted shares should not be considered as an alternative to or more meaningful than common shares as determined in accordance with GAAP as an indicator of the Company’s performance. Debt adjusted shares is a non-GAAP measure used in the calculation of Production per debt adjusted share and is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. Debt adjusted shares should not be considered as an alternative to or more meaningful than weighted average number of common shares (basic) as determined in accordance with GAAP as an indicator of the Company’s performance. Management considers Debt adjusted share is a key performance indicator as it adjusts for the effects of capital structure in relation to the Company’s peers. Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Management considers Production per debt adjusted share is a key performance indicator as it adjusts for the effects of changes in annual production in relation to the Company’s capital structure. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast Production per debt adjusted share.

EV / DAAFF
InPlay uses “enterprise value to debt adjusted AFF” or “EV/DAAFF” as a key performance indicator. EV/DAAFF is calculated by the Company as enterprise value divided by debt adjusted AFF for the relevant period. Debt adjusted AFF (“DAAFF”) is calculated by the Company as adjusted funds flow plus financing costs. Enterprise value is a capital management measures that is used in the calculation of EV/DAAFF. Enterprise value is calculated as the Company’s market capitalization plus net debt. Enterprise value is calculated as market capitalization plus net debt. Management considers enterprise value a key performance indicator as it identifies the total capital structure of the Company. Management considers EV/DAAFF a key performance indicator as it is a key metric used to evaluate the sustainability of the Company relative to other companies while incorporating the impact of differing capital structures. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast 2022 EV/DAAFF.

Capital Management Measures

Adjusted Funds Flow

Management considers adjusted funds flow to be an important measure of InPlay’s ability to generate the funds necessary to finance capital expenditures. Adjusted funds flow is a GAAP measure and is disclosed in the notes to the Company’s consolidated financial statements for the year ending December 31, 2021. All references to adjusted funds flow throughout this document are calculated as funds flow adjusting for decommissioning expenditures and transaction and integration costs. This item is adjusted from funds flow as decommissioning expenditures are incurred on a discretionary and irregular basis and are primarily incurred on previous operating assets and transaction costs are non-recurring costs for the purposes of an acquisition, making the exclusion of these items relevant in Management’s view to the reader in the evaluation of InPlay’s operating performance. The Company also presents adjusted funds flow per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of profit (loss) per common share.

Net Debt

Net debt is a GAAP measure and is disclosed in the notes to the Company’s consolidated financial statements for the year ending December 31, 2021. The Company closely monitors its capital structure with a goal of maintaining a strong balance sheet to fund the future growth of the Company. The Company monitors net debt as part of its capital structure. The Company uses net debt (bank debt plus accounts payable and accrued liabilities less accounts receivables and accrued receivables, prepaid expenses and deposits and inventory) as an alternative measure of outstanding debt. Management considers net debt an important measure to assist in assessing the liquidity of the Company.

Supplementary Measures

“Average realized crude oil price” is comprised of crude oil commodity sales from production, as determined in accordance with IFRS, divided by the Company’s crude oil production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

“Average realized NGL price” is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company’s NGL production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

“Average realized natural gas price” is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company’s natural gas production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

“Average realized commodity price” is comprised of commodity sales from production, as determined in accordance with IFRS, divided by the Company’s production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.

“Adjusted funds flow per weighted average basic share” is comprised of adjusted funds flow divided by the basic weighted average common shares.

“Adjusted funds flow per weighted average diluted share” is comprised of adjusted funds flow divided by the diluted weighted average common shares.

“Adjusted funds flow per boe” is comprised of adjusted funds flow divided by total production.

Forward-Looking Information and Statements This news release contains certain forward–looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”, “forecast” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the recognition of significant additional reserves under the heading “Corporate Reserves Information”, the future net value of InPlay’s reserves, the future development capital and costs, the life of InPlay’s reserves and the net asset values disclosed under the heading “Net Asset Value” including the internal value ascribed to undeveloped acreage; the Company’s planned 2022 capital program including wells to be drilled and completed and the timing of the same; 2022 guidance based on the planned capital program including forecasts of 2022 annual average production levels, debt adjusted production levels, adjusted funds flow, free adjusted funds flow, Net Debt/EBITDA ratio, operating income profit margin, and Management’s belief that the Company can grow some or all of these attributes and specified measures; light crude oil and NGLs weighting estimates; expectations regarding future commodity prices; future oil and natural gas prices; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition, development and infrastructure activities and related capital expenditures, including our planned 2022 capital program; the amount and timing of capital projects; forecasted spending on decommissioning; the expectation that the reserve additions from the Prairie Storm acquisition will generate strong production and FAFF growth; the expectation that InPlay will be in a positive net cash position in the fourth quarter of 2022 using a pricing scenario of US $90 WTI and positive working capital position by 2022 year end; that 2022 will be another record year for the Company; the expectation that the Company will experience inflationary cost pressures in the second half of 2022; the expectation that costs will begin to normalize later in 2022; the Company’s planned 2022 abandonment and reclamation program, including the abandonments and reclamations to be completed, forecasted spending on these activities, reduction to our ARO and forecasted LMR rating; the expectation that the Company will start the second quarter capital program early; the planned release of InPlay’s inaugural sustainability report prior to June 30, 2022 and methods of funding our capital program.

Forward-looking statements or information are based on a number of material factors, expectations or assumptions of InPlay which have been used to develop such statements and information but which may prove to be incorrect. Although InPlay believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because InPlay can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which InPlay operates; the timely receipt of any required regulatory approvals; the ability of InPlay to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which InPlay has an interest in to operate the field in a safe, efficient and effective manner; the ability of InPlay to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and the ability of InPlay to secure adequate product transportation; future commodity prices; that various conditions to a shareholder return strategy can be satisfied; expectations regarding the potential impact of COVID-19; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which InPlay operates; and the ability of InPlay to successfully market its oil and natural gas products.

The forward-looking information and statements included herein are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: the continuing impact of the COVID-19 pandemic; changes in our planned 2022 capital program; changes in commodity prices and other assumptions outlined herein; the potential for variation in the quality of the reservoirs in which we operate; changes in the demand for or supply of our products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans or strategies of InPlay or by third party operators of our properties; increased debt levels or debt service requirements; inaccurate estimation of our light crude oil and natural gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in InPlay’s continuous disclosure documents filed on SEDAR including our Annual Information Form.

The internal projections, expectations or beliefs underlying the Company’s 2022 capital budget, associated guidance and corporate outlook for 2022 and beyond are subject to change in light of ongoing results, prevailing economic circumstances, commodity prices and industry conditions and regulations. InPlay’s outlook for 2022 and beyond provides shareholders with relevant information on management’s expectations for results of operations, excluding any potential acquisitions, dispositions or strategic transactions that may be completed in 2022 and beyond including, without limitation, the potential impact of any shareholder return strategy that may be implemented in the future. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted and InPlay’s 2022 guidance and outlook may not be appropriate for other purposes.

This press release contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about InPlay’s prospective capital expenditures, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. The actual results of operations of InPlay and the resulting financial results will likely vary from the amounts set forth in this press release and such variation may be material. InPlay and its management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. However, because this information is subjective and subject to numerous risks, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, InPlay undertakes no obligation to update such FOFI. FOFI contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about InPlay’s anticipated future business operations. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein.

The forward-looking information and statements contained in this news release speak only as of the date hereof and InPlay does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

InPlay’s 2021 annual guidance and a comparison to 2021 actual results are outlined below.

Notes:

1. As previously released September 28, 2021.
2. As previously released November 30, 2021 (previously $32.5 – $34.5 million on September 28, 2021).
3. This variance is due to the following:
   • Lower fourth quarter sales volumes due to operational downtime caused by extreme cold, third party processing facility mechanical shut downs, a larger build in period ending oil inventories of approximately 9,000 barrels, and the later than initially expected drilling of the two well pad drilled in the fourth quarter of 2021. In addition, new production from the 2021 drilling program had a slightly higher gas weighting and lower NGL yield than forecasted.
   • The effect of shorter royalty incentive periods for recently drilled wells in the improved pricing environment and higher trucking costs on new wells.
   • Significant improvements in the Company’s share price in the later portion of 2021, resulting in additional expenses incurred from the vesting and revaluation of deferred share units, and the accelerated vesting of certain DSUs.
   • Increased hedging losses as a result of higher annual average WTI prices of US $1.06/bbl.
4. This variance is due to the acceleration of the start of the 2022 capital program at the end of 2021 through the initiation of lease construction and starting drilling activities on a three well pad in Pembina due to optimal conditions and availability of services.
5. This net debt variance is due to the higher positive net debt assumed on the Prairie Storm acquisition in addition to additional proceeds from the over-allotment option being exercised on the bought deal financing which both contributed to an additional $3 million positive net debt impact, net of the $4 million reduction to free adjusted funds flow.
6. See “Reader Advisories – Production Breakdown by Product Type”
7. Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release.
8. Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures”

The key budget and underlying material assumptions used by the Company in the development of its 2022 guidance including forecasted production, operating income, capital expenditures, adjusted funds flow, free adjusted funds flow, FAFF yield, Net Debt, Net Debt/EBITDA, EV/DAAFF, production per debt adjusted share growth are as follows:

• See “Production Breakdown by Product Type” below
• Quality and pipeline transmission adjustments may impact realized oil prices in addition to the MSW Differential provided above
• Changes in working capital are not assumed to have a material impact between Dec 31, 2021 and Dec 31, 2022.

Information Regarding Disclosure on Oil and Gas Reserves and Operational Information
Our oil and gas reserves statement for the year ended December 31, 2021, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com on or before March 31, 2022. The recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The Company’s belief that it will establish additional reserves over time with conversion of probable undeveloped reserves into proved reserves is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed above under the heading “Forward-Looking Information and Statements”.

This press release contains metrics commonly used in the oil and natural gas industry, such as “finding, development and acquisition costs”, “finding and development costs”, “operating netbacks”, “recycle ratios”, “reserve replacement” and “reserve life index” or “RLI”. Each of these terms are calculated by InPlay as described in the section “Performance Measures” in this press release. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included herein to provide readers with additional information to evaluate the Company’s performance, however such metrics should not be unduly relied upon.

Finding, development and acquisition (“FD&A”) and finding and development (“F&D”) costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated future development costs may not reflect total finding and development costs related to reserves additions for that year. Finding, development and acquisition costs have been presented in this press release because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure. Exploration & development capital means the aggregate exploration and development costs incurred in the financial year on exploration and on reserves that are categorized as development. Exploration & development capital excludes capitalized administration costs. Acquisition capital amounts to the total amount of cash and share consideration net of any working capital balances assumed with an acquisition on closing.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare InPlay’s operations over time, however such measures are not reliable indicators of InPlay’s future performance and future performance may not be comparable to the performance in prior periods. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes, however such measures are not reliable indicators on InPlay’s future performance and future performance may not be comparable to the performance in prior periods.

References to light crude oil, NGLs or natural gas production in this press release refer to the light and medium crude oil, natural gas liquids and conventional natural gas product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“Nl 51-101“).

Test Results and Initial Production Rates
Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long term performance or of ultimate recovery. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed.

Production Breakdown by Product Type
Disclosure of production on a per boe basis in this press release consists of the constituent product types as defined in NI 51-101 and their respective quantities disclosed in the table below:

Note:

1. This reflects the mid-point of the Company’s 2022 production guidance range of 8,900 to 9,400 boe/d.
2. With respect to forward-looking production guidance, product type breakdown is based upon management’s expectations based on reasonable assumptions but are subject to variability based on actual well results.

References to crude oil, NGLs or natural gas production in this press release refer to the light and medium crude oil, natural gas liquids and conventional natural gas product types, respectively, as defined in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“Nl 51-101”).

BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.

Wednesday, March 16, 2022

Alvopetro Energy (ALVOF)(ALV:CA)
Coverage Initiated With Outperform Rating and a $10 Target

Alvopetro Energy Ltd is a Canada based resource company engaged in the exploration, acquisition, development, and production of hydrocarbons in Brazil. The company holds interests in the Cabure and Gomo natural gas assets, two oil fields (Bom Lugar and Mae-da-lua) and seven other exploration assets in the Reconcavo basin onshore Brazil.

Michael Heim, Senior Research Analyst, Noble Capital Markets, Inc.

Refer to the full report for the price target, fundamental analysis, and rating.

Alvopetro is well positioned to take advantage of the recent rise in energy prices. The price Alvopetro receives is set semi-annually based on oil and gas index pricing, heat content and the Brazilian-U.S. exchange rate. In February 2022, prices rose to approximately $11.28/mcf, a 59% increase over the realized price in the last quarter. With operating costs expected to remain at historical levels, the company should begin to see very large operating netbacks and free cash flow.

Management is in a very enviable position of choosing between expanding or returning proceeds to shareholders.  Most likely, it will do both. An initial dividend set in September has already been raised once to an indicated annual rate of $0.24 per share (yield of 7.0%). At the same time, the company has begun an active drilling program and indicated plans to expand midstream operations. Production …

This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).

*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision. 

Friday, March 11, 2022

Flotek Industries (FTK)
Estimates and Price Target Raised On Transaction Details

Flotek Industries, Inc. creates solutions to reduce the environmental impact of energy on air, water, land and people. Flotek Industries, Inc. is a technology-driven, specialty chemistry and data company that helps customers across industrial, commercial and consumer markets improve their Environmental, Social and Governance performance. Flotek’s Chemistry Technologies segment develops, manufactures, packages, distributes, delivers, and markets high-quality cleaning, disinfecting and sanitizing products for commercial, governmental and personal consumer use. Additionally, Flotek empowers the energy industry to maximize the value of their hydrocarbon streams and improve return on invested capital through its real-time data platforms and green chemistry technologies. Flotek serves downstream, midstream and upstream customers, both domestic and international. Flotek is a publicly traded company headquartered in Houston, Texas, and its common shares are traded on the New York Stock Exchange under the ticker symbol “FTK.” For additional information, please visit Flotek’s web site at www.flotekind.com.

Michael Heim, Senior Research Analyst, Noble Capital Markets, Inc.

Refer to the full report for the price target, fundamental analysis, and rating.

Flotek expands its agreement with Profrac. Revenues now estimated to be $2 billion. Management held a call with analysts and investors to discuss an expansion of its agreement with Profrac. Management was very upbeat about the deal and provided additional details regarding its expectations for revenues ($200 million/year), timing details (in place by summer), and the company’s ability grow supply (plant at 50% capacity, little additional capital required). Management also indicated that it now expects Flotek to be cash flow positive by year end and throughout the life of the contract.

The arrangement provides additional benefits.  In addition to the bottom line, the agreement provides other, less-quantifiable benefits. These include revenue stability, critical mass to expand its customer base and purchase supplies at better rates, and a partner to draw attention to its environmentally-friendly energy solutions. Both firms have an incentive to see the other’s operations grow and …

This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).

*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision. 

  Image: Brookhaven Nat’l Lab (Flickr)

Toward Batteries that Pack Twice as Much Energy Per Pound

 

David L. Chandler | MIT News Office

 

In the endless quest to pack more energy into batteries without increasing their weight or volume, one especially promising technology is the solid-state battery. In these batteries, the usual liquid electrolyte that carries charges back and forth between the electrodes is replaced with a solid electrolyte layer. Such batteries could potentially not only deliver twice as much energy for their size, they also could virtually eliminate the fire hazard associated with today’s lithium-ion batteries.

But one thing has held back solid-state batteries: Instabilities at the boundary between the solid electrolyte layer and the two electrodes on either side can dramatically shorten the lifetime of such batteries. Some studies have used special coatings to improve the bonding between the layers, but this adds the expense of extra coating steps in the fabrication process. Now, a team of researchers at MIT and Brookhaven National Laboratory have come up with a way of achieving results that equal or surpass the durability of the coated surfaces, but with no need for any coatings.

The new method simply requires eliminating any carbon dioxide present during a critical manufacturing step, called sintering, where the battery materials are heated to create bonding between the cathode and electrolyte layers, which are made of ceramic compounds. Even though the amount of carbon dioxide present is vanishingly small in air, measured in parts per million, its effects turn out to be dramatic and detrimental. Carrying out the sintering step in pure oxygen creates bonds that match the performance of the best coated surfaces, without that extra cost of the coating, the researchers say.

The findings are reported in the journal Advanced Energy Materials, in a paper by MIT doctoral student Younggyu Kim, professor of nuclear science and engineering and of materials science and engineering Bilge Yildiz, and Iradikanari Waluyo and Adrian Hunt at Brookhaven National Laboratory.

“Solid-state batteries have been desirable for different reasons for a long time,” Yildiz says. “The key motivating points for solid batteries are they are safer and have higher energy density,” but they have been held back from large scale commercialization by two factors, she says: the lower conductivity of the solid electrolyte, and the interface instability issues.

The conductivity issue has been effectively tackled, and reasonably high-conductivity materials have already been demonstrated, according to Yildiz. But overcoming the instabilities that arise at the interface has been far more challenging. These instabilities can occur during both the manufacturing and the electrochemical operation of such batteries, but for now the researchers have focused on the manufacturing, and specifically the sintering process.

 

These discs were used for testing the researchers’ processing
method for solid-electrolyte batteries. On the left, a sample of the solid
electrolyte itself, a material known as LLPO. At center, the same material
coated with the cathode material used in their tests. At right, the LLPO
material with a coating of gold, used to facilitate measuring its electrical
properties. Credit: Pjotrs Žguns

 

Sintering is needed because if the ceramic layers are simply pressed onto each other, the contact between them is far from ideal, there are far too many gaps, and the electrical resistance across the interface is high. Sintering, which is usually done at temperatures of 1,000 degrees Celsius or above for ceramic materials, causes atoms from each material to migrate into the other to form bonds. The team’s experiments showed that at temperatures anywhere above a few hundred degrees, detrimental reactions take place that increase the resistance at the interface — but only if carbon dioxide is present, even in tiny amounts. They demonstrated that avoiding carbon dioxide, and in particular maintaining a pure oxygen atmosphere during sintering, could create very good bonding at temperatures up to 700 degrees, with none of the detrimental compounds formed.

The performance of the cathode-electrolyte interface made using this method, Yildiz says, was “comparable to the best interface resistances we have seen in the literature,” but those were all achieved using the extra step of applying coatings. “We are finding that you can avoid that additional fabrication step, which is typically expensive.”

The potential gains in energy density that solid-state batteries provide comes from the fact that they enable the use of pure lithium metal as one of the electrodes, which is much lighter than the currently used electrodes made of lithium-infused graphite.

The team is now studying the next part of the performance of such batteries, which is how these bonds hold up over the long run during battery cycling. Meanwhile, the new findings could potentially be applied rapidly to battery production, she says. “What we are proposing is a relatively simple process in the fabrication of the cells. It doesn’t add much energy penalty to the fabrication. So, we believe that it can be adopted relatively easily into the fabrication process,” and the added costs, they have calculated, should be negligible.

Large companies such as Toyota are already at work commercializing early versions of solid-state lithium-ion batteries, and these new findings could quickly help such companies improve the economics and durability of the technology.

The research was supported by the U.S. Army Research Office through MIT’s Institute for Soldier Nanotechnologies. The team used facilities supported by the National Science Foundation and facilities at Brookhaven National Laboratory supported by the Department of Energy.

 

Suggested Reading

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Lithium Prices Continue Their Ascent

EV Inflation Outpacing Traditional Cars

Is the Index Bubble Michael Burry Warned About Still Looming?

 

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Tuesday, March 08, 2022

Indonesia Energy Corp (INDO)
Rating Lowered In Response To Meteoric Rise In Stock Price

Indonesia Energy Corp Ltd is an oil and gas exploration and production company focused on Indonesia. It holds two oil and gas assets through its subsidiaries in Indonesia: one producing block (the Kruh Block) and one exploration block (the Citarum Block). The Kruh Block is located to the northwest of Pendopo, Pali, South Sumatra. The Citarum Block is located to the south of Jakarta.

Michael Heim, Senior Research Analyst, Noble Capital Markets, Inc.

Refer to the full report for the price target, fundamental analysis, and rating.

The shares of INDO have risen from $2.90 at the beginning of the year to $62.46 (up 2054%) briefly trading above $86 at one point. Most of the rise has come in the last five trading days with the stock beginning last week at $13.30. The impetus for the rise was a jump in oil prices (up from $101 to $120 last five trading days). However, the jump in the shares of INDO far surpasses that justified by the rise in oil prices. We would remind investors that there is little to report recently from an operational point of view regarding the company.

The stock price has soared past our price target of $15, which was raised just last Tuesday.  We warned at the time of our price target increase that the shares of INDO are thinly traded and can be volatile. We also said that the increase in our price target was using up our gun powder and that future target increases would be difficult. Now that the stock has risen to a level more than five times …

This Company Sponsored Research is provided by Noble Capital Markets, Inc., a FINRA and S.E.C. registered broker-dealer (B/D).

*Analyst certification and important disclosures included in the full report. NOTE: investment decisions should not be based upon the content of this research summary. Proper due diligence is required before making any investment decision. 

Alvopetro Announces 2021 Year End Reserves With a 52% Increase In 2P NPV Before Tax

News, and Market Data on Alvopetro Energy

 

CALGARY, AB, March 8, 2022 /CNW/ – Alvopetro Energy Ltd. (TSXV:ALV) (OTCQX: ALVOF) announces our reserves as at December 31, 2021 with total proved plus probable (“2P”) reserves of 8.7 mmboe and a before tax net present value discounted at 10% of $297.0 million.  The before tax net present value of our 2P reserves (discounted at 10%) increased by 52% from December 31, 2020, primarily due to increases in forecasted natural gas prices. 2P reserve volumes decreased by 9% due to 2021 production. In addition, Alvopetro announces the December 31, 2021 assessment of the Company’s Murucututu natural gas resource (previously referred to as the Gomo natural gas resource) with risked best estimate contingent resource of 3.5 mmboe and risked best estimate prospective resource of 12.1 mmboe, both of which are virtually unchanged from December 31, 2020.  The Murucututu natural gas contingent and prospective resource values (risked best estimate net present value before tax, discounted at 10%) increased by 61% to $60.7 million and by 44% to $208.7 million, respectively.  The reserves and resources data set forth herein is based on an independent reserves and resources assessment and evaluation prepared by GLJ Ltd. (“GLJ”) dated March 7, 2022 with an effective date of December 31, 2021 (the “GLJ Reserves and Resources Report”).  

All references herein to $ refer to United States dollars, unless otherwise stated.

December 31, 2021 GLJ Reserves and Resource Report Highlights

• 2P net present value before tax discounted at 10% increased 52% to $297.0 million primarily due to higher forecasted commodity prices.
• Proved reserves (“1P”) and 2P reserves decreased to 4.4 mmboe (-13%) and 8.7 mmboe (-9%) respectively, due to 2021 production volumes.
• This represents a 2P Net Asset Value of CAD$11.20/share ($8.77/share).
• Risked best estimate contingent and risked best estimate prospective resource of 3.5 mmboe and 12.1 mmboe, respectively were consistent with prior year with an increase of 61% and 44% respectively on risked best estimate before tax net present value discounted at 10%, due primarily to higher forecasted commodity prices.

Corey Ruttan, President and Chief Executive Officer, commented:

“Our 2021 year-end reserves and resource evaluations highlight the strong profitability from our Caburé natural gas field and the long-term potential of our Murucututu project. The increase in forecasted cash flows reflects the impact of global commodity prices on our forecasted natural gas prices under our long-term gas sales agreement and our most recent price increase effective February 1, 2022. Our 2022 capital program is focused on natural gas exploration and development aimed at expanding our production and reserve base and maximizing the utilization of our strategic midstream infrastructure that is concurrently being expanded to a capacity of at least 500,000 m3/d (17.7 mmcfpd).”

SUMMARY

December 31, 2021 Gross Reserve and Gross Resource Volumes: ^{(1)(5)(6)(7)(8)(9)(10)(11)(14)}

Net present value before tax discounted at 10%:^{(2)(5)(6)(7)(8)(9)(10)(11)(12)(13)}

NET ASSET VALUE

Following the December 31, 2021 reserves evaluation, based on the before tax net present value of Alvopetro’s 2P reserves (discounted at 10%), our total net asset value is $297.3 million; CAD$11.20 per common share outstanding.  Our 2P net asset value of $297.3 million is before including the before tax net present value (discounted at 10%) of our risked best estimate risked contingent resource of $60.7 million and our risked prospective resource of $208.7 million from the Murucututu natural gas field.

PRICING ASSUMPTIONS – FORECAST PRICES AND COSTS 

GLJ employed the following pricing and inflation rate assumptions as of January 1, 2022 in the GLJ Reserves and Resources Report in estimating reserves and resources data using forecast prices and costs.

As of February 1, 2022, Alvopetro’s contracted natural gas price under the terms of our long-term gas sales agreement is based on the ceiling price within the contract and is forecasted to remain at the ceiling price until 2024. The forecasted prices in the GLJ Reserves and Resource Report do not reflect the most recent increase in global commodity prices which further extends the period under which Alvopetro’s contracted price will be at the ceiling in the contract.  The ceiling price incorporates assumed US inflation of 5% in 2022, 3% in 2023 and 2% thereafter.

GLJ RESERVES AND RESOURCES REPORT 

The GLJ Reserves and Resources Report has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGEH”) that are consistent with the standards of National Instrument 51-101 (“NI 51-101”). GLJ is a qualified reserves evaluator as defined in NI 51-101. The GLJ Reserves and Resources Report was an evaluation of all reserves of Alvopetro including our Caburé and Caburé Leste natural gas fields (collectively referred to as our Caburé natural gas field), our Murucututu natural gas project (previously referred to as Gomo), as well as our Bom Lugar and Mãe-da-lua oil fields. The GLJ Reserves and Resources Report also includes an evaluation of the gas resources of our Murucututu natural gas.  In addition to the reserves assigned to our two existing Murucututu wells (197-1 and 183-1) and two additional development locations, contingent resource was assigned to the area in proximity to our existing Murucututu reserves, deemed to be discovered.  The area mapped by 3D seismic west and north of the area defined as contingent was assigned prospective resource. Additional reserves and resources information as required under NI 51-101 will be included in the Company’s Annual Information Form for the 2021 fiscal year which will be filed on SEDAR by April 30, 2022.

December 31, 2021 Reserves Information:

Summary of Reserves ^{(1)(3)(4)(5)(7)(8)}

Summary of Before Tax Net Present Value of Future Net Revenue – MUS ^{(2)(5)(7)(8)(12)(13)}

Summary of After Tax Net Present Value of Future Net Revenue – MUS ^{(2)(5)(7)(8)(12)(13)}

Future Development Costs ^{(2)(5)(7)(8)(12)(13)}

The table below sets out the total development costs deducted in the estimation in the GLJ Reserves and Resources Report of future net revenue attributable to proved reserves, proved plus probable reserves and proved plus probable plus possible reserves (using forecast prices and costs), by field. Total development costs include capital costs for drilling and facility and pipeline expenditures but excludes abandonment and reclamation costs.

Under each reserve category, Alvopetro has elected to reflect 100% of the contractual obligations pursuant to our Gas Treatment Agreement with Enerflex, including all operating, capital, and related financing costs for the full duration of the agreement. These costs are mainly attributable to the Caburé field and also represent the majority of the future development costs for the Caburé field in the table below. The future costs associated with equipment rental are also reflected as a capital lease obligation on our financial statements other than future anticipated equipment rental costs associated with the facility expansion, which will be reflected once completed.

The future development costs for the Murucututu field in the proved category are for the remaining costs anticipated in 2022 for the pipeline and field facility development to tie-in the 183(1) well to Alvopetro’s midstream assets, as well as a development location. In the probable and possible categories, there are future development costs for an additional development location and the stimulation and tie-in of the 197(1) well. Also included in the Murucututu future development costs for all reserve categories are a portion of the anticipated contractual obligations associated with the expansion of the gas treatment facility. The future development costs for Bom Lugar in the proved category include costs for a directional wellbore and facilities upgrade. A second directional well is included in the future development costs for the possible category for Bom Lugar. Future development costs at the Mãe-da-lua field relate to a stimulation of the existing producing well.

Reconciliation of Alvopetro’s Gross Reserves (Before Royalty) ^{(1)(5)(7)(8)(13)}

December 31, 2021 Murucututu Contingent Resources Information:

Summary of Unrisked Company Gross Contingent Resources ^{(1)(3)(4)(5)(7)(10)(11)}

Summary of Before Tax Net Present Value of Future Net Revenue of Unrisked Contingent Resources- MUS ^{(2)(5)(10)(11)(12)(13)}

The GLJ Contingent Resource Report for Murucututu assumes capital deployment during 2023 for the drilling of wells and expansion of facilities, with total project costs of $23.9 million and first commercial production in 2023. There can be no certainty that the project will developed on the timelines discussed herein. Development of the project is dependent on several contingencies as further described in this news release.  The information presented herein is based on company net project development costs.

Summary of Development Pending Risked Company Gross Contingent Resources^{(1)(3)(4)(5)(7)(10)(11)}

The GLJ Reserves and Resources Report estimates the Chance of Development as the product of two main contingencies associated with the project development, which are: 1) the probability of corporate sanctioning, which GLJ estimates at 95%; 2) the probability finalization of a development plan, which GLJ estimates at 95%. The product of these two contingencies is 90%.   As there is no risk related to discovery, the Chance of Commerciality for the contingent resource is therefore 90% which is the risk factor that has been applied to the Development Risked company gross contingent resources and the net present value figures reported below.

Summary of Development Pending Risked Before Tax Net Present Value of Future Net Revenue of Contingent Resources- MUS^{(2)(5)(10)(11)(12)(13)}

December 31, 2021 Murucututu Prospective Resources Information:

Summary of Unrisked Company Gross Prospective Resources ^{(1)(3)(4)(5)(7)(9)(11)}

Summary of Before Tax Net Present Value of Future Net Revenue of Unrisked Prospective Resources- MUS ^{(2)(5)(9)(11)(12)(13)}

The GLJ Prospective Resource Report for Murucututu assumes capital deployment starting 2024 for the drilling of wells, expansion of field facilities, and additional pipeline capacity, with total project costs of $66.1 million and first commercial production in 2024. There can be no certainty that the project will developed on the timelines discussed herein. Development of the project is dependent on several contingencies as further described in this news release.  The information presented herein is based on company project development costs.

The GLJ Reserves and Resources Report estimates the Chance of Commerciality as the product between the Chance of Discovery and the Chance of Development. The Chance of Discovery of the prospective resources has been assessed at 90%, while the Chance of Development has been assessed as the same as for the Contingent Resources described above at 90%. The resulting Chance of Commerciality is 81%, which has been applied to the company gross unrisked prospective resources and the net present value figures reported below.   

Summary of Development Risked Company Gross Prospective Resources^{(1)(3)(4)(5)(7)(9)(11)}

The GLJ Reserves and Resources Report estimates the Chance of Commerciality as the product between the Chance of Discovery and the Chance of Development. The Chance of Discovery of the prospective resources has been assessed at 90%, while the Chance of Development has been assessed as the same as for the Contingent Resources described above at 90%. The resulting Chance of Commerciality is 81%, which has been applied to the company gross unrisked prospective resources and the net present value figures reported below.   

Summary of Development Risked Before Tax Net Present Value of Future Net Revenue of Prospective Resources- MUS^{(2)(5)(9)(11)(12)(13)}

Upcoming 2021 Results and Live Webcast

Alvopetro anticipates announcing its 2021 fourth quarter and year-end results on March 17, 2022 after markets close and will host a live webcast to discuss the results at 8:00 am Mountain time, on the March 18, 2022. Details for joining the event are as follows:

DATE: March 18, 2022TIME: 8:00 AM Mountain/10:00 AM EasternLINK: https://zoom.us/j/99386897923  DIAL-IN NUMBERS: https://zoom.us/u/aixrWbAbO  WEBINAR ID: 993 8689 7923

The webcast will include a question and answer period. Online participants will be able to ask questions through the Zoom portal. Dial-in participants can email questions directly to [email protected].

Corporate Presentation

Alvopetro’s updated corporate presentation is available on our website at:

http://www.alvopetro.com/corporate-presentation. 

FOOTNOTES

Alvopetro Energy Ltd.’s vision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.

All amounts contained in this news release are in United States dollars, except as otherwise noted.

Oil and Natural Gas Reserves. The disclosure in this news release summarizes certain information contained in the GLJ Reserves and Resources Report but represents only a portion of the disclosure required under NI 51-101. Full disclosure with respect to the Company’s reserves as at December 31, 2021 will be contained in the Company’s annual information form for the year ended December 31, 2021 which will be filed on SEDAR (www.sedar.com) on or before April 30, 2022. All net present values in this press release are based on estimates of future operating and capital costs and GLJ’s forecast prices as of December 31, 2021. The reserves definitions used in this evaluation are the standards defined by COGEH reserve definitions and are consistent with NI 51-101 and used by GLJ. The net present values of future net revenue attributable to the Alvopetro’s reserves estimated by GLJ do not represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Contingent Resources. This news release discloses estimates of Alvopetro’s contingent resources and the net present value associated with net revenues associated with the production of such contingent resources as included in the GLJ Reserves and Resources Report. There is no certainty that it will be commercially viable to produce any portion of such contingent resources and the estimated future net revenues do not necessarily represent the fair market value of such contingent resources. Estimates of contingent resources involve additional risks over estimates of reserves. Full disclosure with respect to the Company’s contingent resources as at December 31, 2021 will be contained in the Company’s annual information form for the year ended December 31, 2021 which will be filed on SEDAR (www.sedar.com) on or before April 30, 2022.

Prospective Resources – This news release discloses estimates of Alvopetro’s prospective resources included in the GLJ Reserves and Resources Report. There is no certainty that any portion of the prospective resources will be discovered and even if discovered, there is no certainty that it will be commercially viable to produce any portion. Estimates of prospective resources involve additional risks over estimates of reserves. The accuracy of any resources estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While resources presented herein are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. Full disclosure with respect to the Company’s prospective resources as at December 31, 2021 will be contained in the Company’s annual information form for the year ended December 31, 2021 which will be filed on SEDAR (www.sedar.com) on or before April 30, 2022.

 

BOE Disclosure. The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

Forward-Looking Statements and Cautionary Language. This news release contains “forward-looking information” within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward–looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning the plans relating to the Company’s operational activities and the expected natural gas price, gas sales and gas deliveries under Alvopetro’s long-term gas sales agreement. The forward–looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to equipment availability, the timing of regulatory licenses and approvals, the success of future drilling, completion, testing, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of the COVID-19 pandemic, the performance of producing wells and reservoirs, well development and operating performance, foreign exchange rates, general economic and business conditions, weather and access to drilling locations, the availability and cost of labour and services, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors.  Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our annual information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Non-GAAP Measures. This news release contains financial terms that are not considered measures under International Financial Reporting Standards (“IFRS”), such as working capital net of debt and net asset value. Working capital net of debt is computed as current assets less the sum of current liabilities and the carrying amount of the Company’s credit facility. Net asset value is computed based on the before-tax net present value of the Company’s proved plus probable reserves, discounted at 10%, increased by the Company’s working capital net of debt.  The non-GAAP measures do not have standardized meanings under IFRS and therefore are unlikely to be comparable to similar measures presented by other issuers. While these measures may be common in the oil and gas industry, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. The non-GAAP measures referred to in this report should not be considered an alternative to, or more meaningful than measures prescribed by IFRS and they are not meant to enhance the Company’s reported financial performance or position.  For more information with respect to financial measures which have not been defined by GAAP, including reconciliations to the closest comparable GAAP measure, see the “Non-GAAP Measures” section of the Company’s most recent MD&A which may be accessed through the SEDAR website at www.sedar.com.

SOURCE Alvopetro Energy Ltd.

Carl Icahn Selling into Warren Buffet’s Buying, Can they Both be Right?

 

“We started buying on Monday, and we bought all we could,” Warren Buffett told CNBC. The Berkshire Hathaway CEO was discussing a new 91.2 million share stake his company took in Occidental Petroleum (OXY). At the same time, Carl Icahn, another renowned investor, has been selling shares of OXY. Can they both be right?

 

Warren Buffet on OXY

Buffett pulled the trigger on $4.5 billion of Occidental, an energy exploration and production company, last week.  This gives Berkshire close to a 10% stake in the company. This is an increase in exposure for Berkshire as it also has positions worth $10 billion of preferred shares, along with warrants to buy 83.9 million common shares exercisable at $59.62.

Berkshires 2021 annual report showed they held $144 billion in cash and equivalents.

Carl Icahn on OXY

Billionaire investor Carl Icahn, sold his remaining lot of OXY last week. According to The Wall Street Journal, Icahn made about $1 billion on Occidental stock and still holds about 15 million in warrants (OXY WS). The warrants, which trade at around $34, have an exercise price of $22 a share (current level $57-$58).

Icahn still continues to have exposure to the energy sector through a roughly 6.4% stake worth $2 billion in Cheniere Energy (LNG), a liquefied natural gas producer, and a controlling interest worth $1 billion in CVR Energy (CVI), a petroleum refiner.

The activist investor became involved with Occidental in 2019 around the same time as Buffett. He urged the company to not pursue the debt-financed deal for Anadarko, which Buffett was for and helped enable with loans. Berkshire’s warrants and preferred shares were part of financing the arrangement.

 

Buffett vs Icahn

When you find two legendary investors taking opposite sides of the same trade at the same time, in a sector that is moving quickly, it’s worth stopping to try to understand why. Berkshire Hathaway’s Buffet, who is 91, was a heavy buyer of OXY while Carl Icahn, 86, was selling a huge position put on in 2019.

Description:
Since March 2019 OXY has consistently performed below the energy sector and S&P 500

 

There have been other times when one of these two was buying into the other’s selling. In 2016, Icahn exited a position in Apple (AAPL) he had held for about three years. Also, in 2016 Buffett began scaling into Apple. Icahn made a reported $2 billion profit on 180 million shares of Apple. It is unclear if the redeployment of the proceeds of this sale outpaced the earnings that would have occurred if he held Apple, which has grown 500% since.

Apple has been Buffett’s biggest public market win in the past decade. Berkshire holds about 900 million shares worth $145 billion, more than four times its cost.

Investment Styles

As an activist investor, Icahn’s primary methodology is to own a significant enough amount of a company to influence how the company is run. If a profit presents itself, he is likely to take it. Such was the case with the doubling of OXY in two months’ time this year.

Berkshire’s portfolio is mostly non-public companies it owns outright. As for publicly traded stocks, Buffett’s style is to be patient waiting for value in terms of price and potential.  Buffett has described his favorite holding period as “forever.”

Berkshire is also cash-heavy and should like to deploy $80 billion, but has been priced out of stocks and acquisitions for several years now. With recent market weakness, there may be some big purchases on the horizon.

Take-Away

Investors have different time frames and risk tolerance. More active traders like Icahn may sell if they see other opportunities where they believe the capital could produce a better return, whereas Berkshire’s longer-term view and huge cash position, could make their transactions based on a totally different set of factors. For Berkshire, this purchase may be as easy to understand as asking “do we expect OXY to perform better than cash.”

 

Paul Hoffman

Managing Editor, Channelchek

 

Suggested Reading

Using Warren Buffett’s SEC Filing as an Oracle

Cathie Wood Says Benchmark Funds are Where the Risk Is

Michael Burry vs Cathie Wood is Not an Even Competition

Warren Buffett vs Elon Musk, Who’s Right

 

Sources

https://www.channelchek.com/news-channel/Pros_and_Cons_of_a_Company_Like_Berkshire_Hathaway_in_your_Portfolio

https://www.cnbc.com/2022/03/05/berkshire-hathaway-reveals-5-billion-stake-in-oil-giant-occidental-petroleum.html

https://www.sec.gov/Archives/edgar/data/315090/000089924322009579/xslF345X03/doc4.xml

https://www.barrons.com/articles/warren-buffett-was-buying-occidental-carl-icahn-was-selling-who-will-be-right-51646672487?mod=hp_columnists

 

Stay up to date. Follow us:

Carl Icahn Selling into Warren Buffet’s Buying, Can they Both be Right?

 

“We started buying on Monday, and we bought all we could,” Warren Buffett told CNBC. The Berkshire Hathaway CEO was discussing a new 91.2 million share stake his company took in Occidental Petroleum (OXY). At the same time, Carl Icahn, another renowned investor, has been selling shares of OXY. Can they both be right?

 

Warren Buffet on OXY

Buffett pulled the trigger on $4.5 billion of Occidental, an energy exploration and production company, last week.  This gives Berkshire close to a 10% stake in the company. This is an increase in exposure for Berkshire as it also has positions worth $10 billion of preferred shares, along with warrants to buy 83.9 million common shares exercisable at $59.62.

Berkshires 2021 annual report showed they held $144 billion in cash and equivalents.

Carl Icahn on OXY

Billionaire investor Carl Icahn, sold his remaining lot of OXY last week. According to The Wall Street Journal, Icahn made about $1 billion on Occidental stock and still holds about 15 million in warrants (OXY WS). The warrants, which trade at around $34, have an exercise price of $22 a share (current level $57-$58).

Icahn still continues to have exposure to the energy sector through a roughly 6.4% stake worth $2 billion in Cheniere Energy (LNG), a liquefied natural gas producer, and a controlling interest worth $1 billion in CVR Energy (CVI), a petroleum refiner.

The activist investor became involved with Occidental in 2019 around the same time as Buffett. He urged the company to not pursue the debt-financed deal for Anadarko, which Buffett was for and helped enable with loans. Berkshire’s warrants and preferred shares were part of financing the arrangement.

 

Buffett vs Icahn

When you find two legendary investors taking opposite sides of the same trade at the same time, in a sector that is moving quickly, it’s worth stopping to try to understand why. Berkshire Hathaway’s Buffet, who is 91, was a heavy buyer of OXY while Carl Icahn, 86, was selling a huge position put on in 2019.

Description:
Since March 2019 OXY has consistently performed below the energy sector and S&P 500

 

There have been other times when one of these two was buying into the other’s selling. In 2016, Icahn exited a position in Apple (AAPL) he had held for about three years. Also, in 2016 Buffett began scaling into Apple. Icahn made a reported $2 billion profit on 180 million shares of Apple. It is unclear if the redeployment of the proceeds of this sale outpaced the earnings that would have occurred if he held Apple, which has grown 500% since.

Apple has been Buffett’s biggest public market win in the past decade. Berkshire holds about 900 million shares worth $145 billion, more than four times its cost.

Investment Styles

As an activist investor, Icahn’s primary methodology is to own a significant enough amount of a company to influence how the company is run. If a profit presents itself, he is likely to take it. Such was the case with the doubling of OXY in two months’ time this year.

Berkshire’s portfolio is mostly non-public companies it owns outright. As for publicly traded stocks, Buffett’s style is to be patient waiting for value in terms of price and potential.  Buffett has described his favorite holding period as “forever.”

Berkshire is also cash-heavy and should like to deploy $80 billion, but has been priced out of stocks and acquisitions for several years now. With recent market weakness, there may be some big purchases on the horizon.

Take-Away

Investors have different time frames and risk tolerance. More active traders like Icahn may sell if they see other opportunities where they believe the capital could produce a better return, whereas Berkshire’s longer-term view and huge cash position, could make their transactions based on a totally different set of factors. For Berkshire, this purchase may be as easy to understand as asking “do we expect OXY to perform better than cash.”

 

Paul Hoffman

Managing Editor, Channelchek

 

Suggested Reading

Using Warren Buffett’s SEC Filing as an Oracle

Cathie Wood Says Benchmark Funds are Where the Risk Is

Michael Burry vs Cathie Wood is Not an Even Competition

Warren Buffett vs Elon Musk, Who’s Right

 

Sources

https://channelchek.vercel.app/news-channel/Pros_and_Cons_of_a_Company_Like_Berkshire_Hathaway_in_your_Portfolio

https://www.cnbc.com/2022/03/05/berkshire-hathaway-reveals-5-billion-stake-in-oil-giant-occidental-petroleum.html

https://www.sec.gov/Archives/edgar/data/315090/000089924322009579/xslF345X03/doc4.xml

https://www.barrons.com/articles/warren-buffett-was-buying-occidental-carl-icahn-was-selling-who-will-be-right-51646672487?mod=hp_columnists

 

Stay up to date. Follow us:

Alvopetro Announces 2021 Year End Reserves With a 52% Increase In 2P NPV Before Tax

News, and Market Data on Alvopetro Energy

 

CALGARY, AB, March 8, 2022 /CNW/ – Alvopetro Energy Ltd. (TSXV:ALV) (OTCQX: ALVOF) announces our reserves as at December 31, 2021 with total proved plus probable (“2P”) reserves of 8.7 mmboe and a before tax net present value discounted at 10% of $297.0 million.  The before tax net present value of our 2P reserves (discounted at 10%) increased by 52% from December 31, 2020, primarily due to increases in forecasted natural gas prices. 2P reserve volumes decreased by 9% due to 2021 production. In addition, Alvopetro announces the December 31, 2021 assessment of the Company’s Murucututu natural gas resource (previously referred to as the Gomo natural gas resource) with risked best estimate contingent resource of 3.5 mmboe and risked best estimate prospective resource of 12.1 mmboe, both of which are virtually unchanged from December 31, 2020.  The Murucututu natural gas contingent and prospective resource values (risked best estimate net present value before tax, discounted at 10%) increased by 61% to $60.7 million and by 44% to $208.7 million, respectively.  The reserves and resources data set forth herein is based on an independent reserves and resources assessment and evaluation prepared by GLJ Ltd. (“GLJ”) dated March 7, 2022 with an effective date of December 31, 2021 (the “GLJ Reserves and Resources Report”).  

All references herein to $ refer to United States dollars, unless otherwise stated.

December 31, 2021 GLJ Reserves and Resource Report Highlights

• 2P net present value before tax discounted at 10% increased 52% to $297.0 million primarily due to higher forecasted commodity prices.
• Proved reserves (“1P”) and 2P reserves decreased to 4.4 mmboe (-13%) and 8.7 mmboe (-9%) respectively, due to 2021 production volumes.
• This represents a 2P Net Asset Value of CAD$11.20/share ($8.77/share).
• Risked best estimate contingent and risked best estimate prospective resource of 3.5 mmboe and 12.1 mmboe, respectively were consistent with prior year with an increase of 61% and 44% respectively on risked best estimate before tax net present value discounted at 10%, due primarily to higher forecasted commodity prices.

Corey Ruttan, President and Chief Executive Officer, commented:

“Our 2021 year-end reserves and resource evaluations highlight the strong profitability from our Caburé natural gas field and the long-term potential of our Murucututu project. The increase in forecasted cash flows reflects the impact of global commodity prices on our forecasted natural gas prices under our long-term gas sales agreement and our most recent price increase effective February 1, 2022. Our 2022 capital program is focused on natural gas exploration and development aimed at expanding our production and reserve base and maximizing the utilization of our strategic midstream infrastructure that is concurrently being expanded to a capacity of at least 500,000 m3/d (17.7 mmcfpd).”

SUMMARY

December 31, 2021 Gross Reserve and Gross Resource Volumes: ^{(1)(5)(6)(7)(8)(9)(10)(11)(14)}

Net present value before tax discounted at 10%:^{(2)(5)(6)(7)(8)(9)(10)(11)(12)(13)}

NET ASSET VALUE

Following the December 31, 2021 reserves evaluation, based on the before tax net present value of Alvopetro’s 2P reserves (discounted at 10%), our total net asset value is $297.3 million; CAD$11.20 per common share outstanding.  Our 2P net asset value of $297.3 million is before including the before tax net present value (discounted at 10%) of our risked best estimate risked contingent resource of $60.7 million and our risked prospective resource of $208.7 million from the Murucututu natural gas field.

PRICING ASSUMPTIONS – FORECAST PRICES AND COSTS 

GLJ employed the following pricing and inflation rate assumptions as of January 1, 2022 in the GLJ Reserves and Resources Report in estimating reserves and resources data using forecast prices and costs.

As of February 1, 2022, Alvopetro’s contracted natural gas price under the terms of our long-term gas sales agreement is based on the ceiling price within the contract and is forecasted to remain at the ceiling price until 2024. The forecasted prices in the GLJ Reserves and Resource Report do not reflect the most recent increase in global commodity prices which further extends the period under which Alvopetro’s contracted price will be at the ceiling in the contract.  The ceiling price incorporates assumed US inflation of 5% in 2022, 3% in 2023 and 2% thereafter.

GLJ RESERVES AND RESOURCES REPORT 

The GLJ Reserves and Resources Report has been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGEH”) that are consistent with the standards of National Instrument 51-101 (“NI 51-101”). GLJ is a qualified reserves evaluator as defined in NI 51-101. The GLJ Reserves and Resources Report was an evaluation of all reserves of Alvopetro including our Caburé and Caburé Leste natural gas fields (collectively referred to as our Caburé natural gas field), our Murucututu natural gas project (previously referred to as Gomo), as well as our Bom Lugar and Mãe-da-lua oil fields. The GLJ Reserves and Resources Report also includes an evaluation of the gas resources of our Murucututu natural gas.  In addition to the reserves assigned to our two existing Murucututu wells (197-1 and 183-1) and two additional development locations, contingent resource was assigned to the area in proximity to our existing Murucututu reserves, deemed to be discovered.  The area mapped by 3D seismic west and north of the area defined as contingent was assigned prospective resource. Additional reserves and resources information as required under NI 51-101 will be included in the Company’s Annual Information Form for the 2021 fiscal year which will be filed on SEDAR by April 30, 2022.

December 31, 2021 Reserves Information:

Summary of Reserves ^{(1)(3)(4)(5)(7)(8)}

Summary of Before Tax Net Present Value of Future Net Revenue – MUS ^{(2)(5)(7)(8)(12)(13)}

Summary of After Tax Net Present Value of Future Net Revenue – MUS ^{(2)(5)(7)(8)(12)(13)}

Future Development Costs ^{(2)(5)(7)(8)(12)(13)}

The table below sets out the total development costs deducted in the estimation in the GLJ Reserves and Resources Report of future net revenue attributable to proved reserves, proved plus probable reserves and proved plus probable plus possible reserves (using forecast prices and costs), by field. Total development costs include capital costs for drilling and facility and pipeline expenditures but excludes abandonment and reclamation costs.

Under each reserve category, Alvopetro has elected to reflect 100% of the contractual obligations pursuant to our Gas Treatment Agreement with Enerflex, including all operating, capital, and related financing costs for the full duration of the agreement. These costs are mainly attributable to the Caburé field and also represent the majority of the future development costs for the Caburé field in the table below. The future costs associated with equipment rental are also reflected as a capital lease obligation on our financial statements other than future anticipated equipment rental costs associated with the facility expansion, which will be reflected once completed.

The future development costs for the Murucututu field in the proved category are for the remaining costs anticipated in 2022 for the pipeline and field facility development to tie-in the 183(1) well to Alvopetro’s midstream assets, as well as a development location. In the probable and possible categories, there are future development costs for an additional development location and the stimulation and tie-in of the 197(1) well. Also included in the Murucututu future development costs for all reserve categories are a portion of the anticipated contractual obligations associated with the expansion of the gas treatment facility. The future development costs for Bom Lugar in the proved category include costs for a directional wellbore and facilities upgrade. A second directional well is included in the future development costs for the possible category for Bom Lugar. Future development costs at the Mãe-da-lua field relate to a stimulation of the existing producing well.

Reconciliation of Alvopetro’s Gross Reserves (Before Royalty) ^{(1)(5)(7)(8)(13)}

December 31, 2021 Murucututu Contingent Resources Information:

Summary of Unrisked Company Gross Contingent Resources ^{(1)(3)(4)(5)(7)(10)(11)}

Summary of Before Tax Net Present Value of Future Net Revenue of Unrisked Contingent Resources- MUS ^{(2)(5)(10)(11)(12)(13)}

The GLJ Contingent Resource Report for Murucututu assumes capital deployment during 2023 for the drilling of wells and expansion of facilities, with total project costs of $23.9 million and first commercial production in 2023. There can be no certainty that the project will developed on the timelines discussed herein. Development of the project is dependent on several contingencies as further described in this news release.  The information presented herein is based on company net project development costs.

Summary of Development Pending Risked Company Gross Contingent Resources^{(1)(3)(4)(5)(7)(10)(11)}

The GLJ Reserves and Resources Report estimates the Chance of Development as the product of two main contingencies associated with the project development, which are: 1) the probability of corporate sanctioning, which GLJ estimates at 95%; 2) the probability finalization of a development plan, which GLJ estimates at 95%. The product of these two contingencies is 90%.   As there is no risk related to discovery, the Chance of Commerciality for the contingent resource is therefore 90% which is the risk factor that has been applied to the Development Risked company gross contingent resources and the net present value figures reported below.

Summary of Development Pending Risked Before Tax Net Present Value of Future Net Revenue of Contingent Resources- MUS^{(2)(5)(10)(11)(12)(13)}

December 31, 2021 Murucututu Prospective Resources Information:

Summary of Unrisked Company Gross Prospective Resources ^{(1)(3)(4)(5)(7)(9)(11)}

Summary of Before Tax Net Present Value of Future Net Revenue of Unrisked Prospective Resources- MUS ^{(2)(5)(9)(11)(12)(13)}

The GLJ Prospective Resource Report for Murucututu assumes capital deployment starting 2024 for the drilling of wells, expansion of field facilities, and additional pipeline capacity, with total project costs of $66.1 million and first commercial production in 2024. There can be no certainty that the project will developed on the timelines discussed herein. Development of the project is dependent on several contingencies as further described in this news release.  The information presented herein is based on company project development costs.

The GLJ Reserves and Resources Report estimates the Chance of Commerciality as the product between the Chance of Discovery and the Chance of Development. The Chance of Discovery of the prospective resources has been assessed at 90%, while the Chance of Development has been assessed as the same as for the Contingent Resources described above at 90%. The resulting Chance of Commerciality is 81%, which has been applied to the company gross unrisked prospective resources and the net present value figures reported below.   

Summary of Development Risked Company Gross Prospective Resources^{(1)(3)(4)(5)(7)(9)(11)}

The GLJ Reserves and Resources Report estimates the Chance of Commerciality as the product between the Chance of Discovery and the Chance of Development. The Chance of Discovery of the prospective resources has been assessed at 90%, while the Chance of Development has been assessed as the same as for the Contingent Resources described above at 90%. The resulting Chance of Commerciality is 81%, which has been applied to the company gross unrisked prospective resources and the net present value figures reported below.   

Summary of Development Risked Before Tax Net Present Value of Future Net Revenue of Prospective Resources- MUS^{(2)(5)(9)(11)(12)(13)}

Upcoming 2021 Results and Live Webcast

Alvopetro anticipates announcing its 2021 fourth quarter and year-end results on March 17, 2022 after markets close and will host a live webcast to discuss the results at 8:00 am Mountain time, on the March 18, 2022. Details for joining the event are as follows:

DATE: March 18, 2022TIME: 8:00 AM Mountain/10:00 AM EasternLINK: https://zoom.us/j/99386897923  DIAL-IN NUMBERS: https://zoom.us/u/aixrWbAbO  WEBINAR ID: 993 8689 7923

The webcast will include a question and answer period. Online participants will be able to ask questions through the Zoom portal. Dial-in participants can email questions directly to [email protected].

Corporate Presentation

Alvopetro’s updated corporate presentation is available on our website at:

http://www.alvopetro.com/corporate-presentation. 

FOOTNOTES

Alvopetro Energy Ltd.’s vision is to become a leading independent upstream and midstream operator in Brazil. Our strategy is to unlock the on-shore natural gas potential in the state of Bahia in Brazil, building off the development of our Caburé natural gas field and our strategic midstream infrastructure.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.

All amounts contained in this news release are in United States dollars, except as otherwise noted.

Oil and Natural Gas Reserves. The disclosure in this news release summarizes certain information contained in the GLJ Reserves and Resources Report but represents only a portion of the disclosure required under NI 51-101. Full disclosure with respect to the Company’s reserves as at December 31, 2021 will be contained in the Company’s annual information form for the year ended December 31, 2021 which will be filed on SEDAR (www.sedar.com) on or before April 30, 2022. All net present values in this press release are based on estimates of future operating and capital costs and GLJ’s forecast prices as of December 31, 2021. The reserves definitions used in this evaluation are the standards defined by COGEH reserve definitions and are consistent with NI 51-101 and used by GLJ. The net present values of future net revenue attributable to the Alvopetro’s reserves estimated by GLJ do not represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of the Company’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Contingent Resources. This news release discloses estimates of Alvopetro’s contingent resources and the net present value associated with net revenues associated with the production of such contingent resources as included in the GLJ Reserves and Resources Report. There is no certainty that it will be commercially viable to produce any portion of such contingent resources and the estimated future net revenues do not necessarily represent the fair market value of such contingent resources. Estimates of contingent resources involve additional risks over estimates of reserves. Full disclosure with respect to the Company’s contingent resources as at December 31, 2021 will be contained in the Company’s annual information form for the year ended December 31, 2021 which will be filed on SEDAR (www.sedar.com) on or before April 30, 2022.

Prospective Resources – This news release discloses estimates of Alvopetro’s prospective resources included in the GLJ Reserves and Resources Report. There is no certainty that any portion of the prospective resources will be discovered and even if discovered, there is no certainty that it will be commercially viable to produce any portion. Estimates of prospective resources involve additional risks over estimates of reserves. The accuracy of any resources estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While resources presented herein are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. Full disclosure with respect to the Company’s prospective resources as at December 31, 2021 will be contained in the Company’s annual information form for the year ended December 31, 2021 which will be filed on SEDAR (www.sedar.com) on or before April 30, 2022.

 

BOE Disclosure. The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this news release are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

Forward-Looking Statements and Cautionary Language. This news release contains “forward-looking information” within the meaning of applicable securities laws. The use of any of the words “will”, “expect”, “intend” and other similar words or expressions are intended to identify forward-looking information. Forward–looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning the plans relating to the Company’s operational activities and the expected natural gas price, gas sales and gas deliveries under Alvopetro’s long-term gas sales agreement. The forward–looking statements are based on certain key expectations and assumptions made by Alvopetro, including but not limited to equipment availability, the timing of regulatory licenses and approvals, the success of future drilling, completion, testing, recompletion and development activities, the outlook for commodity markets and ability to access capital markets, the impact of the COVID-19 pandemic, the performance of producing wells and reservoirs, well development and operating performance, foreign exchange rates, general economic and business conditions, weather and access to drilling locations, the availability and cost of labour and services, environmental regulation, including regulation relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors.  Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our annual information form which may be accessed on Alvopetro’s SEDAR profile at www.sedar.com. The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Non-GAAP Measures. This news release contains financial terms that are not considered measures under International Financial Reporting Standards (“IFRS”), such as working capital net of debt and net asset value. Working capital net of debt is computed as current assets less the sum of current liabilities and the carrying amount of the Company’s credit facility. Net asset value is computed based on the before-tax net present value of the Company’s proved plus probable reserves, discounted at 10%, increased by the Company’s working capital net of debt.  The non-GAAP measures do not have standardized meanings under IFRS and therefore are unlikely to be comparable to similar measures presented by other issuers. While these measures may be common in the oil and gas industry, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. The non-GAAP measures referred to in this report should not be considered an alternative to, or more meaningful than measures prescribed by IFRS and they are not meant to enhance the Company’s reported financial performance or position.  For more information with respect to financial measures which have not been defined by GAAP, including reconciliations to the closest comparable GAAP measure, see the “Non-GAAP Measures” section of the Company’s most recent MD&A which may be accessed through the SEDAR website at www.sedar.com.

SOURCE Alvopetro Energy Ltd.